Non-emulsifier for completion brines to prevent emulsion from forming

ABSTRACT

Non-emulsifying compositions may contain one or more sorbitan esters; one or more non-ionic surfactants; and one or more amphoteric surfactants, wherein the ratio of the one or more sorbitan esters to the one or more non-ionic surfactants to the one or more amphoteric surfactants is in the range of 1:1:1 to 1:5:3. Methods may include contacting an emulsion with a treatment fluid, the treatment fluid containing one or more sorbitan esters, one or more non-ionic surfactants, and one or more amphoteric surfactants, wherein the ratio of the one or more sorbitan esters to the one or more non-ionic surfactants to the one or more amphoteric surfactants is in the range of 1:1:1 to 1:5:3; and separating the emulsion into an aqueous phase and an oleaginous phase.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority, pursuant to 35 U.S.C. § 119(e) to U.S. Provisional Application 62/243,980 filed on Oct. 20, 2015, which is incorporated by reference in its entirety.

BACKGROUND

During the drilling of a wellbore, various fluids are used in the well for a variety of functions. The fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through wellbore to the surface. During this circulation, a drilling fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.

Once injected, wellbore fluids may be subjected to various contaminants, including drill cuttings, mud residues, and various connate fluids. The presence of contaminants and residues in the wellbore may also be composed of chemical phases that are distinct from the injected fluid and may form emulsions or sludge when admixture occurs. Emulsions produced may be detrimental to wellbore operations, and can result in formation damage, adverse changes in fluid rheology, or introduce additional impurities into produced hydrocarbons. When the wellbore fluid is a fracturing fluid, viscous emulsions may form when oils are contacted downhole, which may inhibit the ability to pump the fluids further into a formation, increasing the energy required and raising operating costs.

SUMMARY

In one aspect, embodiments disclosed herein relate to a composition that includes one or more sorbitan esters; one or more non-ionic surfactants; and one or more amphoteric surfactants, wherein the ratio of the one or more sorbitan esters to the one or more non-ionic surfactants to the one or more amphoteric surfactants is in the range of 1:1:1 to 1:5:3.

In another aspect, embodiments disclosed herein relate to a method that includes emplacing a wellbore fluid into a wellbore, the wellbore fluid including a base fluid; one or more sorbitan esters; one or more non-ionic surfactants; and one or more amphoteric surfactants, wherein the ratio of the one or more sorbitan esters to the one or more non-ionic surfactants to the one or more amphoteric surfactants is in the range of 1:1:1 to 1:5:3.

In yet another aspect, embodiments disclosed herein relate to a method that includes: contacting an emulsion with a treatment fluid and separating the emulsion into an aqueous phase and an oleaginous phase. The treatment fluid may include: one or more sorbitan esters, one or more non-ionic surfactants, and one or more amphoteric surfactants, wherein the ratio of the one or more sorbitan esters to the one or more non-ionic surfactants to the one or more amphoteric surfactants is in the range of 1:1:1 to 1:5:3.

Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

DETAILED DESCRIPTION

In one aspect, non-emulsifying surfactants of the present disclosure may be used as a wellbore fluid additive that prevents or modifies the degree of emulsion formation between injected fluids and fluids present downhole. Wellbore fluids in accordance with the present disclosure may be formulated with a surfactant package that maintains the interfacial boundary between injected fluids and reservoir crude oil and other oleaginous fluids. In some embodiments, the non-emulsifying surfactant packages may include a predetermined ratio of one or more nonionic surfactants, sorbitan esters, and amphoteric surfactants. Further, surfactant compositions of the present disclosure may also be formulated from components that meet the requirements for use in environmentally sensitive applications.

The occurrence of emulsions is a natural phenomenon of oil extraction from reservoirs containing systems of oil, water, and gas. When emulsions are formed with aqueous fluids, particularly those with high salt content, the emulsions exhibit viscosities greater than that of the dehydrated oil. For example, emulsions and sludge may form between crude oils and aqueous fluids due to the presence of hydrocarbon components such as asphaltenes, resins, and asphaltogenic acids. The presence of emulsions can affect the sizing and power output of the pumping system, the transfer and storage of petroleum mixtures, and may also generate problems of encrustation and corrosion in oil pipelines carrying the outflow. Emulsion creation may also increase in the later stages of production where the oil-water contact approaches the bottom of the wellbore. This may lead to increases in turbulent flow from the formation of water-in-oil emulsions.

Controlling emulsion formation may decrease the total cost of operation by reducing energy consumption, pump stress and failures, and need for topside emulsion breaker chemicals. Further, partitioning aqueous and oleaginous fluids may decrease the cost of separating captured crude oils from wellbore wastes, which may obviate the need to transport of the emulsion to the surface for treatment, in addition to reducing the amount of emulsified fluid that would otherwise require time and expense to transport and separate.

In order to combat problems associated with emulsion formation, non-emulsifying surfactant packages in accordance with the present disclosure may be used during wellbore operations in wells that are generating mixtures of aqueous and oleaginous fluids. Non-emulsifying surfactants may aid the separation of commingled fluids by partitioning produced hydrocarbon fluids from injected fluids and/or connate fluids produced during flowback. Use of non-emulsifying surfactants may also aid the maintenance of phase separation between aqueous and oleaginous phases, and decrease pumping pressure required to inject and remove emulsified fluids.

As used herein, the term “environmentally friendly” is defined as chemicals or formulations that can pass the most stringent environmental testing criteria as described below. Furthermore, as used herein, the term “environmentally unfriendly” is defined as chemicals or formulations that do not pass the most stringent environmental testing criteria. Specifically, one of the measures of sample toxicological test is marine biodegradation on a component level as outlined in the Organization for Economic Cooperation and Development, Procedure OECD 306 or BODIS. In the North Sea offshore environment, OSPAR prescreening scheme is followed to determine if a substance would be a candidate for “substitution warning” classification (i.e., chemical substances identified as candidates for substitution). The ecotoxicity test requirements are: bioaccumulation, biodegradation in sea water or fresh water, and toxicity testing on specific North Sea species such as Skeletonema costatum, Acartia tonsa, and juvenile turbot. In order for a chemical to be used without any implications offshore in the North Sea it must satisfy two of the following three criterion:

(1) Biodegradation: >60% in 28 days as measured by OECD 306 or any other OSPAR-accepted marine protocols, or in the absence of valid results for such tests, >60% in 28 days as measured by OECD 301B, 301C, 301D, 301F, 310, Freshwater BODIS or >70% in 28 days as measured by OECD 301A, 301E;

(2) Bioaccumulation: a bioconcentration factor (BCF)<100 determined according to OECD 305 or ASTM E 1022 guidelines, or log P_(ow) (partition coefficient of a substance between N-octanol and water, measured or calculated according to the HOCNF Guidelines or an OECD 107 test)≤3 and molecular weight >700, or if the conclusion of a weight of evidence expert judgment under Appendix 3 of OSPAR Agreement 2008-5 is positive; and

(3) Aquatic Toxicity: LC50>10 mg/l or EC50>10 mg/1; if toxicity values >10 mg/l are derived from limit tests to fish, actual fish LC50 data should be submitted in accordance with OSPAR Guidelines for Completing the HOCNF. In particular embodiments, each of the three criteria are met.

At present (and for the last 30 years), the geographic location with the most stringent environmental and discharge testing criteria for well treatment operation is the North Sea, but the definition of either of these terms should in no way be limited to any past, present or future North Sea environmental testing criteria. Further, the test criteria also in no way limit the geographical region of use of the fluid, but provide an indication of the environmental friendliness of a product (or fluid containing a product).

As solutions are found useful to provide certain functions in treatment fluids, when used in the North Sea off shore, or other highly regulated off shore environments, stringent requirements for particular off shore environments are met. Any oilfield chemical that is used in the North Sea is registered with the respective country's regulatory body which assigns a rating or color classification to each chemical depending on its environmental and toxicological characteristics. Based on the chemical rating or color classification, the chemical will either be regarded as more or less environmentally friendly or unfriendly. In the North Sea, the classification techniques vary. For example, Norway and Denmark follow color classification for chemical products, United Kingdom (UK) follows color and letter ratings for organic and inorganic chemical products, respectively, and Netherlands follows letter categories. Thus, countries within a small geographic region have customized their classification system based upon a desire to differentiate environmentally friendly and unfriendly chemical products. Regardless of the classification system, each of the North Sea countries (Norway, Denmark, Netherlands and United Kingdom) employs the same three ecotoxicology tests criteria described above to differentiate chemical products.

When each component in a chemical product passes the above mentioned criteria, then typically the whole product can be termed as “Green” or PLONOR (Pose Little Or NO Risk) in Norway and Denmark. When all the components in a product meets two of the criteria, then the product can receive “Yellow” classification in Norway and Denmark, and still considered as environmentally friendly. If the biodegradation value in seawater or fresh eater is <20% after 28 days for any of the components or if toxicity (LC50 or EC50) of an inorganic component is less than 1 mg/L, then the chemical products can receive “Red” classification or substitution warning (i.e., environmentally unfriendly classification in the North Sea). Table 1, below, summarizes the North Sea regulations. As a rule of thumb, two or more “Good” results means that the chemical compounds are acceptable, while two or more “Bad” results means that the chemical compound is unacceptable. However, a chemical compound having less than 20% biodegradation alone or an LC50 or EC50 of less than 1 mg/L may end up with environmentally unfriendly classification in the North Sea and could be unacceptable.

TABLE 1 North Sea Regulations Interpretation Test Biodegradation Bioaccumulation Toxicity - EC/LC50 Unit % Log Pow mg/L Result <20 20-60 >60 <3 >3 <1 <10 >10 Inference Very Bad Good Good Bad Very Bad Good bad bad

Surfactant packages in accordance with the present disclosure are water-soluble or water-dispersible, and may be used as non-emulsifying additives, demulsifiers, viscosity reducers, and/or emulsion modifiers. In one or more embodiments, non-emulsifying surfactant packages are a mixture of one or more surfactants that may be added to an aqueous wellbore fluid to prevent the creation of an emulsion or dispersion by, for example, maintaining the interfacial tension between the two liquid phases. It is also envisioned that surfactant packages in accordance with the present disclosure may also contribute to friction reduction during pressure pumping treatments in wells where the presence of oleaginous fluids is not detected or anticipated.

In one or more embodiments, non-emulsifying surfactants in accordance with the present disclosure may be formulated as part of a wellbore fluid injected during completions. Completion fluids are solids-free, or low-solid, liquids used to “complete” an oil or gas well prior to initiation of production, such as during setting screens production liners, packers, downhole valves or shooting perforations into the producing zone. Completions fluids may be used to control a well should downhole hardware fail, without damaging the producing formation or completion components. In some embodiments, completion fluids may be brines such as chlorides, bromides, and formates, but may also be any fluid of proper density and flow characteristics. Other applications include formulation as a reservoir drill-in fluid that is used in drilling operations through hydrocarbon producing intervals of a wellbore to minimize formation damage. Still other applications include the treatment of fracturing fluids or acid treatments to prevent the formation of emulsions and sludges with hydrocarbon fluids produced from the formation.

In another aspect, embodiments disclosed herein may relate to methods for breaking formed emulsions in mud slop and other waste waters, separating the treated fluids into oleaginous and clarified aqueous phases during crude oil production and/or refinery processes. Non-emulsifying surfactant packages may also be used to remove an oil or water phase from waste streams or breaking down viscosity of sludges in order to promote solids separation and removal. Following treatment processes of the present disclosure, the resulting water phase may be clarified to a sufficiently high purity to meet local regulatory limits for discharge to the environment, particularly prior to overboard discharge.

In one or more embodiments, the clarified aqueous phase of a treated wellbore fluid may be separated and recycled for use in future wellbore operations. For example, recovered aqueous fluids may be treated with a surfactant package in accordance with the present disclosure, separated, and re-injected directly or supplemented with additional surfactant prior to use. In some embodiments, non-emulsifiers may also be used to break formed emulsions into their constituent phases, which may find utility in certain operations such as chemical analysis of oil and synthetic muds and to treat produced hydrocarbons.

Nonionic Surfactants

In one or more embodiments, surfactant packages in accordance with the present disclosure may include a nonionic surfactant. Nonionic surfactants may promote coalescence of oleaginous phase droplets and aid transport to the phase boundary to maintain the separation between aqueous and oleaginous phases. In one or more embodiments nonionic surfactants in accordance with the present disclosure may include compounds that act as wetting agents or coagulants that act to aggregate solids present in a wellbore fluid.

In some embodiments, nonionic surfactants may include primary alcohol alkoxylates, secondary alcohol alkoxylates, fatty alcohol alkoxylates, alkoxylated fatty acids, fatty acid ester soaps, alkylphenol ethers, alkyl phosphates, silicone glycol copolymers, phosphate esters, glucosides such as cetearyl glucoside, alkyl polyglucosides, and alkoxylated triglycerides, and mixtures thereof. Further, one of ordinary skill would appreciate that this list is not exhaustive, and that other surface active agents may be used in accordance with embodiments of the present disclosure.

Nonionic surfactants may also include ethylene oxide polymers, copolymers and block copolymers of poly(ethylene oxide-propylene oxide) (PEO-PPO) with different ethylene oxide (EO) to propylene oxide (PO) molar ratios, and poloxamers. In some embodiments, nonionic surfactants may be selected from commercially available surfactants such as Pluronic® polymers, including AP and AE type, available from BASF, and compounds such as Kemelix® family of ethoxylated surfactants, including 3515X, 3551X, 3697X, 3702X, 3725X, 3736X, 3738X, 3743X, 3744X, and D510, surfactants from Croda International.

In one or more embodiments, the nonionic surfactant may also be selected on the basis of have a hydrophilic/lipophilic balance (HLB) of the surfactant. The term “HLB” (Hydrophilic Lipophilic Balance) refers to the ratio of the hydrophilicity of the polar groups of the surface-active molecules to the hydrophobicity of the lipophilic part of the same molecules. In some embodiments, the HLB may be within the range of 7-11, or from 8-10.

Nonionic surfactants in accordance with the present disclosure may be used at percent by volume (vol %) in the range of about 0.1 vol % to about 5 vol % of wellbore fluid in some embodiments, and from 0.5 vol % to 3 vol % in other embodiments. However, one of ordinary skill in the art would appreciate that in other embodiments, more or less may be used.

Sorbitan Esters

In one or more embodiments, surfactant packages in accordance with the present disclosure may include a sorbitan ester surfactant. Soribitan esters in accordance with the present disclosure may include alkoxylated sorbitan esters in which hydroxyl groups of the sorbitan nucleus are modified to include at least one C8-C22 alkyl or alkenyl ether, such as ethylene glycol, polypropylene glycol, and mixtures, polymers, copolymers, and block copolymers thereof, and a mono-, di-, or tri-esters of C8-C22 alkyl or alkenyl fatty acids. For example, sorbitan ester surfactants may be a polysorbate, such as polyoxyethylene (20) sorbitan monolaurate, polyoxyethylene (20) sorbitan monoplamitate, polyoxyethylene (20) sorbitan monooleate, and polyoxyethylene (20) sorbitan monostearate. Sorbitan esters may also include sorbitans esterified with mono-, di-, tri-, or tetra-esters of C8-C22 alkyl or alkenyl fatty acids, such as sorbitan monolaurate, sorbitan dialurate, sorbitan monopalmitate, sorbitan dipalmitate, sorbitan monooleate, sorbitan dioleate, etc.

Sorbitan esters in accordance with the present disclosure may be used at a percent by volume (vol %) in the range of about 0.1 vol % to about 5 vol % of wellbore fluid in some embodiments, and from 0.5 vol % to 3 vol % in other embodiments. However, one of ordinary skill in the art would appreciate that in other embodiments, more or less may be used.

The sorbate ester surfactant may be selected based on the environmental safety constraints in place in the given region in which the wellbore operation takes place, and the average molecular weight (M_(w)) of the nonionic surfactant may be greater than 700 Da in some embodiments.

Amphoteric Surfactants

In one or more embodiments, surfactant packages in accordance with the present disclosure may include an amphoteric surfactant Amphoteric surfactants may interact at an oil/water interface through a mixture of electrostatic and steric effects, which can result in enhanced phase separation. For example, amphoteric surfactants may reduce the surface charge sufficiently to produce oil droplet coalescence and separation.

In one or more embodiments, the amphoteric surfactant may be selected from C8-C22 alkyl amidopropyl sultaines, C8-C22 alkyl amidopropyl betaines, C8-C22 alkenyl amidopropyl betaines, alkyl amphohydroxypropyl sulfonates, alkyl ampho(di)acetates, and mixtures thereof. In some embodiments, the amphoteric surfactant may be a commercially available amphoteric wetting agent such as CAS 50 available from commercially available from Croda International, or Mirataine Bet O-30, a betaine surfactant, commercially available from Rhodia.

Amphoteric surfactants in accordance with the present disclosure may be used at a percent by volume (vol %) ranging from 0.1 vol % to about 5 vol % of wellbore fluid in some embodiments, and from 0.5 vol % to 3 vol % in other embodiments. However, one of ordinary skill in the art would appreciate that in other embodiments, more or less may be used.

In one or more embodiments, surfactants of the present disclosure may include a surfactant blend that is mixed in ratios of sorbitan ester:nonionic surfactant:amphoteric surfactant in the range of 1:1:1 to 1:5:3. In some embodiments, the ratio of sorbitan ester:nonionic surfactant:amphoteric surfactant may be 1:2.5:1.6.

Non-emulsifying surfactant packages may be added to a wellbore fluid at a concentration of 0.1 vol % to 10 vol % of the wellbore fluid in some embodiments, and from 0.2 vol % to 3 vol % in other embodiments. However, care must be taken in selecting a particular range for a given wellbore fluid because the addition of excess surfactant may result in the formation and stabilization of emulsions.

Prepared surfactant packages may also be diluted to contain a fraction of actives that are diluted with water or a compatible solvent in some embodiments. For example, surfactant packages of the present disclosure may include a working concentration that has been diluted to a final working concentration of 5 vol % to 75 vol % of active components, and from 15 vol % to 50 vol % in some embodiments.

Base Fluid

Base fluids useful for preparing wellbore fluid formulations in accordance with the present disclosure may include at least one of fresh water, sea water, brine, mixtures of water and water-soluble organic compounds, and mixtures thereof. In various embodiments, the aqueous fluid may be a brine, which may include seawater, aqueous solutions wherein the salt concentration is less than that of sea water, or aqueous solutions wherein the salt concentration is greater than that of sea water. Salts that may be found in seawater include, but are not limited to, sodium, calcium, aluminum, magnesium, potassium, strontium, and lithium salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, sulfates, silicates, phosphates and fluorides. Salts that may be incorporated in a brine include any one or more of those present in natural seawater or any other organic or inorganic dissolved salts.

Additionally, brines that may be used in the wellbore fluids disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution. In one embodiment, the density of the wellbore fluid may be controlled by increasing the salt concentration in the brine (up to saturation, for example). In a particular embodiment, a brine may include halide or carboxylate salts of mono- or divalent cations of metals, such as cesium, potassium, calcium, zinc, and/or sodium.

Other suitable base fluids useful in methods described herein may be oil-in-water emulsions or water-in-oil emulsions in one or more embodiments. Suitable oil-based or oleaginous fluids that may be used to formulate emulsions may include a natural or synthetic oil and in some embodiments, in some embodiments the oleaginous fluid may be selected from the group including diesel oil; mineral oil; a synthetic oil, such as hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl ethers of fatty acids, mixtures thereof and similar compounds known to one of skill in the art; and mixtures thereof.

Base fluids in accordance with the present disclosure may be added to a surfactant package in a range of 25 vol % to 90 vol % in some embodiments, and from 30 vol % to 75 vol % in other embodiments.

In one or more embodiments, non-emulsifying surfactant packages may be formulated to contain a mutual solvent mutual solvent, examples of which include a glycol ether or glycerol. The use of the term “mutual solvent” includes its ordinary meaning as recognized by those skilled in the art, as having solubility in both aqueous and oleaginous fluids. In some embodiments, the mutual solvent may be substantially completely soluble in each phase while in select other embodiment, a lesser degree of solubilization may be acceptable. Illustrative examples of such mutual solvents include for example, alcohols, linear or branched such as isopropanol, methanol, glycerol, or glycols and glycol ethers such as 2-methoxyethanol, 2-propoxyethanol, 2-ethoxyethanol, diethylene glycol monoethyl ether, dipropylene glycol monomethyl ether, tripropylene glycol monomethyl ether, ethylene glycol monobutyl ether, ethylene glycol dibutyl ether, diethylene glycol monoethyl ether, diethyleneglycol monomethyl ether, tripropylene butyl ether, dipropylene glycol butyl ether, diethylene glycol butyl ether, butylcarbitol, dipropylene glycol methyl ether, propylene glycol n-propyl ether, propylene glycol t-butyl ether, ether, and various esters, such as ethyl lactate, propylene carbonate, butylene carbonate, and the like, and pyrrolidones.

Mutual solvents in accordance with the present disclosure may be added to a surfactant package in a range of 2.5 vol % to 30 vol % in some embodiments, and from 5 vol % to 25 vol % in other embodiments.

EXAMPLES

In the following examples, the non-emulsion forming properties of various surfactants and packages were studied using a variation of a bottle test to measure phase separation in which a brine treated with a selected surfactant was mixed with various samples of crude oil.

Example 1

In a first example, various surfactants were assayed to determine their compatibility with selected brines and crude oil samples. During the test, 10 mL of brine treated with a specified surfactant was added to a graduated cylinder, followed by 10 mL of crude oil and incubated in a water bath set to 150° F. (66° C.). The volume of brine phase and oil phase was then monitored over time and recorded at 10 minute intervals. Phase separation was determined by dividing the initial brine volume to calculate the percentage of phase separation. For example, phase separation may be calculated as (V₁/V₂)*100, where V₁ is the volume of separated water and V₂ is the original volume of water contained.

Surfactants studied were L1505, a sorbitan ester; Kemelix 3702X, a nonionic surfactant; and CAS 50, an amphoteric surfactant. Surfactant samples were mixed in calcium bromide or calcium chloride brine, and combined with crude oils A-1578 from Tatweer Bahrain; and RP 10 and FRADE from Brazil. Results of the separation tests are shown below in Tables 1 and 2.

TABLE 1 Crude Compatibility Test Results of A-1578 with single component in 13.0 ppg CaBr₂ brine Concen- Non- tration Separation (%) after emulsifier (v/vol %) 10 min 20 min 30 min Appearance L 1505 0.05 89 98 100 Large droplet macro- 0.5 vol % emulsion formed in aqueous phase 0.25 73 87 90 Large droplet macro- emulsion formed in aqueous phase 0.75 82 87 90 Large droplet macro- emulsion formed in aqueous phase Kemelix 0.05 82 88 92 Clear aqueous phase 3702X 0.25 60 77 84 Clear aqueous phase 0.25 vol % 0.75 40 57 66 Clear aqueous phase CAS 50 0.05 46 66 74 Aqueous phase hazy in appearance 0.25 vol % 0.25 8 24 38 Aqueous phase hazy in appearance 0.75 34 55 64 Aqueous phase hazy in appearance

TABLE 2 Crude Compatibility Test Results of FRADE with single component in 11.0 ppg CaCl₂ brine Concen- Non- tration Separation (%) after emulsifier (v/vol %) 10 min 20 min 30 min Appearance L 1505 0.05 ~100 ~100 ~100 Large droplet oil 0.5 suspension formed vol % in aqueous phase 0.25 ~100 ~100 ~100 Large droplet oil suspension formed in aqueous phase 0.5  80 ~100 ~100 Large droplet oil suspension formed in aqueous phase Kemelix 0.05 80 80 82 Hazy aqueous phase 3702X 0.25 84 92 94 Hazy aqueous phase 0.25 0.5  76 84 88 Hazy aqueous phase vol % CAS 50 0.05 72 80 84 Hazy aqueous phase 0.25 0.25 84 88 92 Hazy aqueous phase vol % 0.5  70 80 84 Hazy aqueous phase

Example 2

In the next example, a surfactant package in accordance with the present disclosure (M1) was formulated from L1505, Kemelix 3702X, and CAS 50, combined at a ratio 1:2.5:1.6. A comparative surfactant formulation (C2) was prepared from L1505 and Kemelix 3702X at a ratio of 1:3 (0.05 vol % L1505 to 0.15 vol % Kemelix 3702X), without an added amphoteric surfactant. Compatibility tests were conducted as discussed in Example 1. Results are show in Table 3.

TABLE 3 Non-emulsification properties of surfactant package and a comparative formulation. Separa- Oleaginous Surfactant Time tion Brine Fluid Package (min) (%) Appearance CaBr₂ A-1578 C2 10 92 Slightly hazy aq. phase 20 98 Slightly hazy aq. phase 30 100 Slightly hazy aq. phase M1 10 99 Slightly hazy aq. phase 0.5 vol % 20 100 Slightly hazy aq. phase 30 100 Slightly hazy aq. phase CaCl₂ A-1578 C2 10 30 Heavy discoloration in aq. phase 20 54 Heavy discoloration in aq. phase 30 64 Heavy discoloration in aq. phase M1 10 80 Slight oil suspension in 1.0 vol % aq. phase 20 94 Slight oil suspension in aq. phase 30 100 Slight oil suspension in aq. phase CaCl₂ RP 10 C2 10 68 Heavy discoloration in aq. phase 20 80 Heavy discoloration in aq. phase 30 88 Slight discoloration M1 10 80 Slightly hazy aqueous 0.5 vol % phase 20 94 Slightly hazy aqueous phase 30 100 Slightly hazy aqueous phase CaBr₂ FRADE C2 10 84 Clear aqueous phase 20 90 Clear aqueous phase 30 92 Clear aqueous phase M1 10 99 Clear aqueous phase 0.5 vol % 20 100 Clear aqueous phase 30 100 Clear aqueous phase

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112(f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function. 

What is claimed is:
 1. A composition comprising: one or more sorbitan esters; one or more non-ionic surfactants; and one or more amphoteric surfactants, wherein the ratio of the one or more sorbitan esters to the one or more non-ionic surfactants to the one or more amphoteric surfactants is in the range of 1:2.5:1.6 to 1:5:3.
 2. The composition of claim 1, wherein the one or more sorbitan esters are selected from the group consisting of alkoxylated sorbitan esters, polysorbates, and sorbitans esterified with mono-, di-, tri-, or tetra-esters of C8-C22 alkyl or alkenyl fatty acids.
 3. The composition of claim 1, wherein the one or more nonionic surfactants are selected from the group consisting of ethylene oxide polymers, copolymers and block copolymers of polyethylene oxide-propylene oxide), and poloxamers.
 4. The composition of claim 1, wherein the one or more amphoteric surfactants are selected from the group consisting of C8-C22 alkyl amidopropyl sultaines, C8-C22 alkyl amidopropyl betaines, C8-C22 alkenyl amidopropyl betaines, alkyl amphohydroxypropyl sulfonates, and alkyl ampho(di)acetates.
 5. The composition of claim 1, wherein the composition further comprises a base fluid.
 6. The composition of claim 5, wherein the base fluid is present at a concentration in the range of 30 vol % to 75 vol %.
 7. The composition of claim 1, further comprising a mutual solvent.
 8. A method comprising: emplacing a wellbore fluid into a wellbore, the wellbore fluid comprising: a base fluid; one or more sorbitan esters; one or more non-ionic surfactants; and one or more amphoteric surfactants, wherein the ratio of the one or more sorbitan esters to the one or more non-ionic surfactants to the one or more amphoteric surfactants is in the range of 1:2.5:1.6 to 1:5:3.
 9. The method of claim 8, further comprising: contacting the wellbore fluid with an emulsion in the wellbore; and separating the emulsion into an aqueous phase and an oleaginous phase.
 10. The method of claim 8, wherein the one or more sorbitan esters are selected from the group consisting of alkoxylated sorbitan esters, polysorbates, and sorbitans esterified with mono-, di-, tri-, or tetra-esters of C8-C22 alkyl or alkenyl fatty acids.
 11. The method of claim 8, wherein the one or more nonionic surfactants are selected from the group consisting of ethylene oxide polymers, copolymers and block copolymers of poly(ethylene oxide-propylene oxide), and poloxamers.
 12. The method of claim 8, wherein the one or more amphoteric surfactants are selected from the group consisting of C8-C22 alkyl amidopropyl sultaines, C8-C22 alkyl amidopropyl betaines, C8-C22 alkenyl amidopropyl betaines, alkyl amphohydroxypropyl sulfonates, and alkyl ampho(di)acetates.
 13. The method of claim 8, wherein the ratio of sorbitan ester:nonionic surfactant:amphoteric surfactant is 1:2.5:1.6.
 14. The method of claim 8, wherein the wellbore fluid further comprises a mutual solvent.
 15. A method comprising: contacting an emulsion with a treatment fluid, the treatment fluid comprising: one or more sorbitan esters, one or more non-ionic surfactants, and one or more amphoteric surfactants, wherein the ratio of the one or more sorbitan esters to the one or more non-ionic surfactants to the one or more amphoteric surfactants is in the range of 1:2.5:1.6 to 1:5:3; and separating the emulsion into an aqueous phase and an oleaginous phase.
 16. The method of claim 15, further comprising: isolating the separated aqueous phase; and injecting the separated aqueous phase into a wellbore.
 17. The method of claim 15, wherein the one or more sorbitan esters are selected from the group consisting of alkoxylated sorbitan esters, polysorbates, and sorbitans esterified with mono-, di-, tri-, or tetra-esters of C8-C22 alkyl or alkenyl fatty acids.
 18. The method of claim 15, wherein the one or more nonionic surfactants are selected from the group consisting of ethylene oxide polymers, copolymers and block copolymers of poly(ethylene oxide-propylene oxide), and poloxamers.
 19. The method of claim 15, wherein the one or more amphoteric surfactants are selected from the group consisting of C8-C22 alkyl amidopropyl sultaines, C8-C22 alkyl amidopropyl betaines, C8-C22 alkenyl amidopropyl betaines, alkyl amphohydroxypropyl sulfonates, and alkyl ampho(di)acetates.
 20. The method of claim 15, wherein the treatment fluid further comprises a mutual solvent. 